Method and composition for enhanced hydrocarbons recovery

ABSTRACT

A method of treating a hydrocarbon containing formation, comprising (a) providing a composition to at least a portion of the hydrocarbon containing formation, wherein the composition comprises a derivative selected from the group consisting of a carboxylate or a sulfate or glycerol sulfonate of an ethoxylated/propoxylated primary alcohol having a branched aliphatic group with an average carbon number from 10 to 24 and having an average number of branches per aliphatic group of from 0.7 to 2.5 and having at least 0.5 moles of propylene oxide per mole of primary alcohol and having at least 0.5 moles of ethylene oxide per mole of primary alcohol; and (b) allowing the composition to interact with hydrocarbons in the hydrocarbon containing formation.

PRIORITY CLAIM

The present application claims priority to U.S. Provisional PatentApplication No. 61/026,931 filed 7 Feb. 2008 and U.S. Provisional PatentApplication No. 61/026,944 filed 7 Feb. 2008.

FIELD OF THE INVENTION

The present invention generally relates to methods for recovery ofhydrocarbons from hydrocarbon formations. More particularly, embodimentsdescribed herein relate to methods of enhanced hydrocarbons recovery andto compositions useful therein.

BACKGROUND OF THE INVENTION

Hydrocarbons may be recovered from hydrocarbon containing formations bypenetrating the formation with one or more wells. Hydrocarbons may flowto the surface through the wells. Conditions (e.g., permeability,hydrocarbon concentration, porosity, temperature, pressure) of thehydrocarbon containing formation may affect the economic viability ofhydrocarbon production from the hydrocarbon containing formation. Ahydrocarbon containing formation may have natural energy (e.g., gas,water) to aid in mobilizing hydrocarbons to the surface of thehydrocarbon containing formation. Natural energy may be in the form ofwater. Water may exert pressure to mobilize hydrocarbons to one or moreproduction wells. Gas may be present in the hydrocarbon containingformation at sufficient pressures to mobilize hydrocarbons to one ormore production wells. The natural energy source may become depletedover time. Supplemental recovery processes may be used to continuerecovery of hydrocarbons from the hydrocarbon containing formation.Examples of supplemental processes include waterflooding, polymerflooding, alkali flooding, thermal processes, solution flooding orcombinations thereof.

In chemical Enhanced Oil Recovery (EOR) the mobilization of residual oilsaturation is achieved through surfactants which generate a sufficiently(ultra) low crude oil/water interfacial tension (IFT) to give acapillary number large enough to overcome capillary forces and allow theoil to flow (I. Chatzis and N. R. Morrows, “Correlation of capillarynumber relationship for sandstone”. SPE Journal, Vol 29, pp 555-562,1989.) However, reservoirs have different characteristics (crude oiltype, temperature and the water composition—salinity, hardness) and itis desirable that the structures of added surfactant(s) be matched tothese conditions to achieve a low IFT. In addition, a promisingsurfactant must fulfill other important criteria including low rockretention, compatibility with polymer, thermal and hydrolytic stabilityand acceptable cost.

Compositions and methods for enhanced hydrocarbons recovery aredescribed in U.S. Pat. No. 3,943,160 to Farmer et al., entitled“Heat-Stable Calcium-Compatible Waterflood Surfactant;” U.S. Pat. No.3,946,812 to Gale et al., entitled “Use Of Materials As WaterfloodAdditives;” U.S. Pat. No. 4,077,471 to Shupe et al., entitled“Surfactant Oil Recovery Process Usable In High Temperature, HighSalinity Formations;” U.S. Pat. No. 4,216,079 to Newcombe, entitled“Emulsion Breaking With Surfactant Recovery;” U.S. Pat. No. 5,318,709 toWuest et al., entitled “Process for the Production of SurfactantMixtures Based On Ether Sulfonated And Their Use;” U.S. Pat. No.5,723,423 to Van Slyke, entitled “Solvent Soaps and Methods EmployingSame;” U.S. Pat. No. 6,022,834 to Hsu et al., entitled “AlkalineSurfactant Polymer Flooding Composition and Process;” U.S. Pat. No.6,269,881 to Chou et al., entitled “Oil Recovery Method For Waxy CrudeOil Using Alkylaryl Sulfonate Surfactants Derived From Alpha-Olefins andthe Alpha-Olefin Compositions” and by Wellington, et al. in “LowSurfactant Concentration Enhanced Waterflooding,” Society of PetroleumEngineers, 1995; all of which are incorporated by reference herein.

U.S. Pat. No. 7,055,602 describes enhanced hydrocarbons recoverycompositions containing aliphatic nonionic additives and/or thealiphatic anionic surfactants that have branched structures. Theseadditives and surfactants may be primary alcohols or sulfates thereofhaving branched aliphatic groups which may have an average carbon numberfrom 10 to 24, less than about 0.5 percent quaternary carbon atoms, anaverage number of branches per aliphatic group of the aliphatic anionicsurfactant may range between about 0.7 and about 2.5, and methylbranches may represent between about 20 percent to about 99 percent ofthe total number of branches present in the group. Such compositions areshown in Table of that patent to achieve interfacial tensions of from0.0022 (low range) to 1.9040 (high range) dynes/cm when used alone or incombination with other materials.

U.S. Pat. No. 4,293,428 describes enhanced hydrocarbons recoverycompositions containing derivatives of alcohols having an average carbonnumber from 6 to 24 and 1 to 10 propoxy groups and 1 to 10 ethoxygroups. The preferred alcohol precursors are branched alcohols having anaverage carbon number from 10 to 16 and having at least two branchinggroups. Only i-tridecyl alcohol alkoxylated sulfate is exemplified. Nointerfacial tension data is provided.

SUMMARY OF THE INVENTION

In an embodiment, hydrocarbons may be produced from a hydrocarboncontaining formation by a method that includes treating at least aportion of the hydrocarbon containing formation with a hydrocarbonrecovery composition. In certain embodiments, at least a portion of thehydrocarbon containing formation may be oil wet. In some embodiments, atleast a portion of the hydrocarbon formation may include low salinitywater. In other embodiments, at least a portion of the hydrocarboncontaining formation may exhibit an average temperature of greater thanabout 30° C., even greater than about 60° C. Fluids, substances orcombinations thereof may be added to at least a portion of thehydrocarbon containing formation to aid in mobilizing hydrocarbons toone or more production wells in certain embodiments.

In one embodiment, the hydrocarbon recovery composition may include aderivative selected from the group consisting of a carboxylate or asulfate or a glycerol sulfonate of a ethoxylated/propoxylated primaryalcohol having a branched aliphatic group with an average carbon numberfrom 10 to 24 and having an average number of branches per aliphaticgroup of from about 0.7 to about 2.5. The amount of propylene oxideadded to the primary alcohol may be at least about 0.5, preferably fromabout 3 to about 12, most preferably from about 4 to about 7, moles ofpropylene oxide per mole of primary alcohol. The amount of ethyleneoxide added to the alcohol may be at least about 0.5, preferably fromabout 1.5 to about 5, most preferably from about 2 to about 4, moles ofethylene oxide per mole of primary alcohol.

The derivative may have an average carbon number of at least 14 or itmay range from 14 to 20. As used herein, the phrase “carbon number”refers to the total number of carbons in a molecule. The average carbonnumber may be determined by NMR analysis. The average number of branchesper molecule of the derivative may be at least about 2 in someembodiments. Branches on the branched derivative may include, but arenot limited to, methyl and/or ethyl branches. In some embodiments, theaverage number of branches per molecule may be at least about 1 and/orup to about 3 or up to about 6 or up to about 10. The average number ofbranches per molecule may also be determined by NMR analysis.

In one embodiment, the hydrocarbon recovery composition may include acarboxylate or a sulfate or a glycerol sulfonate of anethoxylated/propoxylated branched primary alcohol having a branchedaliphatic group with an average carbon number from 16 to 19, preferably16 to 17, and having an average number of branches per aliphatic groupof from about 0.7 to about 2.5. In one embodiment the hydrocarbonrecovery composition an average number of branches per aliphatic groupof from about 1.4 to about 2. In one embodiment, methyl groups mayrepresent from about 20 to about 99 percent of the total number ofbranches present in the branched aliphatic group.

In an embodiment, the hydrocarbon recovery composition may comprise fromabout 10 to about 80 wt % of the derivative, preferably from about 10 toabout 40 wt % and more preferably from about 20 to about 30 wt %. In anembodiment, a hydrocarbon containing composition may be produced from ahydrocarbon containing formation. The hydrocarbon containing compositionmay include any combination of hydrocarbons, the derivatives describedabove, a solubilizing agent, methane, water, asphaltenes, carbonmonoxide and ammonia.

In an embodiment, the hydrocarbon recovery composition is provided tothe hydrocarbon containing formation by admixing it with water and/orbrine which may be from the formation from which hydrocarbons are to beextracted. Preferably, the composition comprises from about 0.1 to about4 wt % of the total water and/or brine/hydrocarbon recovery compositionmixture (the injectable fluid). More important is the amount of actualactive matter that is present in the injectable fluid (active matter isthe surfactant, here the derivative). Thus, the amount of the derivativein the injectable fluid may be from about 0.1 to about 1 wt %,preferably from about 0.2 to about 0.5 wt %. The injectable fluid isthen injected into the hydrocarbon containing formation.

BRIEF DESCRIPTION OF THE DRAWINGS

Advantages of the present invention will become apparent to thoseskilled in the art with the benefit of the following detaileddescription of embodiment and upon reference to the accompanyingdrawings, in which:

FIG. 1 depicts an embodiment of treating a hydrocarbon containingformation;

FIG. 2 depicts an embodiment of treating a hydrocarbon containingformation;

FIG. 3 depicts a graphical representation of interfacial tension valuesof a hydrocarbon composition containing glycerol carboxylates accordingto the present invention.

While the invention is susceptible to various modifications andalternative forms, specific embodiments thereof are shown by way ofexample in the drawings and will herein be described in detail. Itshould be understood that the drawing and detailed description theretoare not intended to limit the invention to the particular formdisclosed, but on the contrary, the intention is to cover allmodifications, equivalents and alternatives falling within the spiritand scope of the present invention as defined by the appended claims.

DETAILED DESCRIPTION OF EMBODIMENTS

Hydrocarbons may be produced from hydrocarbon formations through wellspenetrating a hydrocarbon containing formation. “Hydrocarbons” aregenerally defined as molecules formed primarily of carbon and hydrogenatoms such as oil and natural gas. Hydrocarbons may also include otherelements, such as, but not limited to, halogens, metallic elements,nitrogen, oxygen and/or sulfur. Hydrocarbons derived from a hydrocarbonformation may include, but are not limited to, kerogen, bitumen,pyrobitumen, asphaltenes, oils or combinations thereof. Hydrocarbons maybe located within or adjacent to mineral matrices within the earth.Matrices may include, but are not limited to, sedimentary rock, sands,silicilytes, carbonates, diatomites and other porous media.

A “formation” includes one or more hydrocarbon containing layers, one ormore non-hydrocarbon layers, an overburden and/or an underburden. An“overburden” and/or an “underburden” includes one or more differenttypes of impermeable materials. For example, overburden/underburden mayinclude rock, shale, mudstone, or wet/tight carbonate (i.e., animpermeable carbonate without hydrocarbons). For example, an underburdenmay contain shale or mudstone. In some cases, the overburden/underburdenmay be somewhat permeable. For example, an underburden may be composedof a permeable mineral such as sandstone or limestone. In someembodiments, at least a portion of a hydrocarbon containing formationmay exist at less than or more than 1000 feet below the earth's surface.

Properties of a hydrocarbon containing formation may affect howhydrocarbons flow through an underburden/overburden to one or moreproduction wells. Properties include, but are not limited to, porosity,permeability, pore size distribution, surface area, salinity ortemperature of formation. Overburden/underburden properties incombination with hydrocarbon properties, such as, capillary pressure(static) characteristics and relative permeability (flow)characteristics may effect mobilization of hydrocarbons through thehydrocarbon containing formation.

Permeability of a hydrocarbon containing formation may vary depending onthe formation composition. A relatively permeable formation may includeheavy hydrocarbons entrained in, for example, sand or carbonate.“Relatively permeable,” as used herein, refers to formations or portionsthereof, that have an average permeability of 10 millidarcy or more.“Relatively low permeability” as used herein, refers to formations orportions thereof that have an average permeability of less than about 10millidarcy. One darcy is equal to about 0.99 square micrometers. Animpermeable portion of a formation generally has a permeability of lessthan about 0.1 millidarcy. In some cases, a portion or all of ahydrocarbon portion of a relatively permeable formation may includepredominantly heavy hydrocarbons and/or tar with no supporting mineralgrain framework and only floating (or no) mineral matter (e.g., asphaltlakes).

Fluids (e.g., gas, water, hydrocarbons or combinations thereof) ofdifferent densities may exist in a hydrocarbon containing formation. Amixture of fluids in the hydrocarbon containing formation may formlayers between an underburden and an overburden according to fluiddensity. Gas may form a top layer, hydrocarbons may form a middle layerand water may form a bottom layer in the hydrocarbon containingformation. The fluids may be present in the hydrocarbon containingformation in various amounts. Interactions between the fluids in theformation may create interfaces or boundaries between the fluids.Interfaces or boundaries between the fluids and the formation may becreated through interactions between the fluids and the formation.Typically, gases do not form boundaries with other fluids in ahydrocarbon containing formation. In an embodiment, a first boundary mayform between a water layer and underburden. A second boundary may formbetween a water layer and a hydrocarbon layer. A third boundary may formbetween hydrocarbons of different densities in a hydrocarbon containingformation. Multiple fluids with multiple boundaries may be present in ahydrocarbon containing formation, in some embodiments. It should beunderstood that many combinations of boundaries between fluids andbetween fluids and the overburden/underburden may be present in ahydrocarbon containing formation.

Production of fluids may perturb the interaction between fluids andbetween fluids and the overburden/underburden. As fluids are removedfrom the hydrocarbon containing formation, the different fluid layersmay mix and form mixed fluid layers. The mixed fluids may have differentinteractions at the fluid boundaries. Depending on the interactions atthe boundaries of the mixed fluids, production of hydrocarbons maybecome difficult. Quantification of the interactions (e.g., energylevel) at the interface of the fluids and/or fluids andoverburden/underburden may be useful to predict mobilization ofhydrocarbons through the hydrocarbon containing formation.

Quantification of energy required for interactions (e.g., mixing)between fluids within a formation at an interface may be difficult tomeasure. Quantification of energy levels at an interface between fluidsmay be determined by generally known techniques (e.g., spinning droptensiometer). Interaction energy requirements at an interface may bereferred to as interfacial tension. “Interfacial tension” as usedherein, refers to a surface free energy that exists between two or morefluids that exhibit a boundary. A high interfacial tension value (e.g.,greater than about 10 dynes/cm) may indicate the inability of one fluidto mix with a second fluid to form a fluid emulsion. As used herein, an“emulsion” refers to a dispersion of one immiscible fluid into a secondfluid by addition of a composition that reduces the interfacial tensionbetween the fluids to achieve stability. The inability of the fluids tomix may be due to high surface interaction energy between the twofluids. Low interfacial tension values (e.g., less than about 1 dyne/cm)may indicate less surface interaction between the two immiscible fluids.Less surface interaction energy between two immiscible fluids may resultin the mixing of the two fluids to form an emulsion. Fluids with lowinterfacial tension values may be mobilized to a well bore due toreduced capillary forces and subsequently produced from a hydrocarboncontaining formation.

Fluids in a hydrocarbon containing formation may wet (e.g., adhere to anoverburden/underburden or spread onto an overburden/underburden in ahydrocarbon containing formation). As used herein, “wettability” refersto the preference of a fluid to spread on or adhere to a solid surfacein a formation in the presence of other fluids. Methods to determinewettability of a hydrocarbon formation are described by Craig, Jr. in“The Reservoir Engineering Aspects of Waterflooding”, 1971 MonographVolume 3, Society of Petroleum Engineers, which is herein incorporatedby reference. In an embodiment, hydrocarbons may adhere to sandstone inthe presence of gas or water. An overburden/underburden that issubstantially coated by hydrocarbons may be referred to as “oil wet.” Anoverburden/underburden may be oil wet due to the presence of polarand/or heavy hydrocarbons (e.g., asphaltenes) in the hydrocarboncontaining formation. Formation composition (e.g., silica, carbonate orclay) may determine the amount of adsorption of hydrocarbons on thesurface of an overburden/underburden. In some embodiments, a porousand/or permeable formation may allow hydrocarbons to more easily wet theoverburden/underburden. A substantially oil wet overburden/underburdenmay inhibit hydrocarbon production from the hydrocarbon containingformation. In certain embodiments, an oil wet portion of a hydrocarboncontaining formation may be located at less than or more than 1000 feetbelow the earth's surface.

A hydrocarbon formation may include water. Water may interact with thesurface of the underburden. As used herein, “water wet” refers to theformation of a coat of water on the surface of theoverburden/underburden. A water wet overburden/underburden may enhancehydrocarbon production from the formation by preventing hydrocarbonsfrom wetting the overburden/underburden. In certain embodiments, a waterwet portion of a hydrocarbon containing formation may include minoramounts of polar and/or heavy hydrocarbons.

Water in a hydrocarbon containing formation may contain minerals (e.g.,minerals containing barium, calcium, or magnesium) and mineral salts(e.g., sodium chloride, potassium chloride, magnesium chloride). Watersalinity and/or water hardness of water in a formation may affectrecovery of hydrocarbons in a hydrocarbon containing formation. As usedherein “salinity” refers to an amount of dissolved solids in water.“Water hardness,” as used herein, refers to a concentration of divalentions (e.g., calcium, magnesium) in the water. Water salinity andhardness may be determined by generally known methods (e.g.,conductivity, titration). As used herein, “high salinity water” refersto water that has greater than about 30,000 ppm total dissolved solidsbased on sodium chloride. As water salinity increases in a hydrocarboncontaining formation, interfacial tensions between hydrocarbons andwater may be increased and the fluids may become more difficult toproduce.

Low salinity water in a hydrocarbon containing formation may enhancehydrocarbon production from a hydrocarbon containing formation.Hydrocarbons and low salinity water may form a well dispersed emulsiondue to a low interfacial tension between the low salinity water and thehydrocarbons. Production of a flowable emulsion (e.g.,hydrocarbons/water mixture) from a hydrocarbon containing formation maybe more economically viable to a producer. As used herein, “low salinitywater” refers to water salinity in a hydrocarbon containing formationthat is less than about 20,000 parts per million (ppm) total dissolvedsolids based on sodium chloride. In some embodiments, hydrocarboncontaining formations may include water with a salinity of less thanabout 13,000 ppm. In certain embodiments, hydrocarbon containingformations may include water with a salinity ranging from about 3,000ppm to about 10,000 ppm. In other embodiments, salinity of the water inhydrocarbon containing formations may range from about 5,000 ppm toabout 8,000 ppm.

A hydrocarbon containing formation may be selected for treatment basedon factors such as, but not limited to, thickness of hydrocarboncontaining layers within the formation, assessed liquid productioncontent, location of the formation, salinity content of the formation,temperature of the formation, and depth of hydrocarbon containinglayers. Initially, natural formation pressure and temperature may besufficient to cause hydrocarbons to flow into well bores and out to thesurface. Temperatures in a hydrocarbon containing formation may rangefrom about 0° C. to about 300° C. As hydrocarbons are produced from ahydrocarbon containing formation, pressures and/or temperatures withinthe formation may decline. Various forms of artificial lift (e.g.,pumps, gas injection) and/or heating may be employed to continue toproduce hydrocarbons from the hydrocarbon containing formation.Production of desired hydrocarbons from the hydrocarbon containingformation may become uneconomical as hydrocarbons are depleted from theformation.

Mobilization of residual hydrocarbons retained in a hydrocarboncontaining formation may be difficult due to viscosity of thehydrocarbons and capillary effects of fluids in pores of the hydrocarboncontaining formation. As used herein “capillary forces” refers toattractive forces between fluids and at least a portion of thehydrocarbon containing formation. In an embodiment, capillary forces maybe overcome by increasing the pressures within a hydrocarbon containingformation. In other embodiments, capillary forces may be overcome byreducing the interfacial tension between fluids in a hydrocarboncontaining formation. The ability to reduce the capillary forces in ahydrocarbon containing formation may depend on a number of factors,including, but not limited to, the temperature of the hydrocarboncontaining formation, the salinity of water in the hydrocarboncontaining formation, and the composition of the hydrocarbons in thehydrocarbon containing formation.

As production rates decrease, additional methods may be employed to makea hydrocarbon containing formation more economically viable. Methods mayinclude adding sources of water (e.g., brine, steam), gases, polymers,monomers or any combinations thereof to the hydrocarbon formation toincrease mobilization of hydrocarbons.

In an embodiment, a hydrocarbon containing formation may be treated witha flood of water. A waterflood may include injecting water into aportion of a hydrocarbon containing formation through injections wells.Flooding of at least a portion of the formation may water wet a portionof the hydrocarbon containing formation. The water wet portion of thehydrocarbon containing formation may be pressurized by known methods anda water/hydrocarbon mixture may be collected using one or moreproduction wells. The water layer, however, may not mix with thehydrocarbon layer efficiently. Poor mixing efficiency may be due to ahigh interfacial tension between the water and hydrocarbons.

Production from a hydrocarbon containing formation may be enhanced bytreating the hydrocarbon containing formation with a polymer and/ormonomer that may mobilize hydrocarbons to one or more production wells.The polymer and/or monomer may reduce the mobility of the water phase inpores of the hydrocarbon containing formation. The reduction of watermobility may allow the hydrocarbons to be more easily mobilized throughthe hydrocarbon containing formation. Polymers include, but are notlimited to, polyacrylamides, partially hydrolyzed polyacrylamide,polyacrylates, ethylenic copolymers, biopolymers,carboxymethylcellulose, polyvinyl alcohol, polystyrene sulfonates,polyvinylpyrrolidone, AMPS (2-acrylamide-2-methyl propane sulfonate) orcombinations thereof. Examples of ethylenic copolymers includecopolymers of acrylic acid and acrylamide, acrylic acid and laurylacrylate, lauryl acrylate and acrylamide. Examples of biopolymersinclude xanthan gum and guar gum. In some embodiments, polymers may becrosslinked in situ in a hydrocarbon containing formation. In otherembodiments, polymers may be generated in situ in a hydrocarboncontaining formation. Polymers and polymer preparations for use in oilrecovery are described in U.S. Pat. No. 6,427,268 to Zhang et al.,entitled “Method For Making Hydrophobically Associative Polymers,Methods of Use and Compositions;” U.S. Pat. No. 6,439,308 to Wang,entitled “Foam Drive Method;” U.S. Pat. No. 5,654,261 to Smith,entitled, “Permeability Modifying Composition For Use In Oil Recovery;”U.S. Pat. No. 5,284,206 to Surles et al., entitled “Formation Treating;”U.S. Pat. No. 5,199,490 to Surles et al., entitled “Formation Treating”and U.S. Pat. No. 5,103,909 to Morgenthaler et al., entitled “ProfileControl In Enhanced Oil Recovery,” all of which are incorporated byreference herein.

The Hydrocarbon Recovery Composition

This family of anionic surfactants based on these randomly branchedalcohols is useful for use under higher salinity reservoir conditions.In this family the connecting group PO links the alcohol hydrophobe tothe anionic sulfonate and is used to change the HLB of the molecule andmatch it to reservoir conditions in terms of salinity and crude oil. Thepresence of PO chains in the connecting group helps to provide toleranceto Ca, Mg ions in hard water.

In an embodiment, a hydrocarbon recovery composition may be provided tothe hydrocarbon containing formation. In an embodiment, the compositionmay include a derivative selected from the group consisting of acarboxylate or a sulfate or glycerol sulfonate of aethoxylated/propoxylated primary alcohol having a branched aliphaticgroup with an average carbon number from 10 to 24 and having an averagenumber of branches per aliphatic group of from about 0.7 to about 2.5.The derivative may have an average carbon number of at least 14 or itmay range from 14 to 20. In some embodiments, the average number ofbranches per molecule may be at least about 1 and/or up to about 3 or upto about 6 or up to about 10.

In one embodiment, the hydrocarbon recovery composition may include acarboxylate or a sulfate or a glycerol sulfonate of anethoxylated/propoxylated branched primary alcohol having a branchedaliphatic group with an average carbon number from 16 to 19, preferably16 to 17, and having an average number of branches per aliphatic groupof from about 0.7 to about 2.5, preferably about 1.4 to about 2.

Branched primary alcohols according to the present invention may beprepared by hydroformylation of a branched olefin. Preparations ofbranched olefins are described in U.S. Pat. No. 5,510,306 to Murray,entitled “Process For Isomerizing Linear Olefins to Isoolefins;” U.S.Pat. No. 5,648,584 to Murray, entitled “Process For Isomerizing LinearOlefins to Isoolefins” and U.S. Pat. No. 5,648,585 to Murray, entitled“Process For Isomerizing Linear Olefins to Isoolefins,” all of which areincorporated by reference herein. Preparations of branched long chainaliphatic alcohols are described in U.S. Pat. No. 5,849,960 to Singletonet al., entitled “Highly Branched Primary Alcohol Compositions, andBiodegradable Detergents Made Therefrom;” U.S. Pat. No. 6,150,222 toSingleton et al., entitled “Highly Branched Primary AlcoholCompositions, and Biodegradable Detergents Made Therefrom;” U.S. Pat.No. 6,222,077 to Singleton et al., entitled “Highly Branched PrimaryAlcohol Compositions, and Biodegradable Detergents Made Therefrom,” allof which are incorporated by reference herein.

In some embodiments, the branches of the branched aliphatic group of thelong chain primary alcohol may have less than about 0.5 percentaliphatic quaternary carbon atoms. In an embodiment, an average numberof branches per long chain aliphatic alcohol ranges from about 0.1 toabout 2.5. In other embodiments, an average number of branches peralcohol ranges from about 0.7 to about 2.5.

Methyl branches may represent between about 20 percent to about 99percent of the total number of branches present in the branched longchain primary alcohol. In some embodiments, methyl branches mayrepresent greater than about 50 percent of the total number of branchesin a branched long chain primary alcohol. The number of ethyl branchesin the alcohol may represent, in certain embodiments, less than about 30percent of the total number of branches. In other embodiments, thenumber of ethyl branches, if present, may be between about 0.1 percentand about 2 percent of the total number of branches. Branches other thanmethyl or ethyl, if present, may be less than about 10 percent of thetotal number of branches. In some embodiments, less than about 0.5percent of the total number of branches are neither ethyl or methylgroups.

This family of anionic surfactants based on these randomly branchedalcohols is useful for use under higher salinity reservoir conditions.In this family the connecting group (of EO and PO) links the alcoholhydrophobe to the anionic sulfonate or sulfate or carboxylate and isused to change the HLB of the molecule and match it to reservoirconditions in terms of salinity and crude oil. The presence of PO chainsin the connecting group helps to provide tolerance to Ca, Mg ions inhard water.

The amount of propylene oxide added to the primary alcohol may be atleast about 0.5, preferably from about 3 to about 12, most preferablyfrom about 4 to about 7, moles of propylene oxide per mole of primaryalcohol. It is preferred that at least about 3 moles per mole of primaryalcohol be utilized in order to minimize the amount of unalkoxylatedprimary alcohol. It is preferred that no more than about 9 moles permole of primary alcohol be used because the molecule loses its abilityto function as a surfactant when the carbon chain on the alcohol portionis too short relative to the amount of propylene oxide in the molecule.In order for the molecule to function successfully as a surfactant inthe hydrocarbon containing formation, there must be a proper balancebetween the length of the oil soluble carbon chain part of the moleculeand the water soluble propylene oxide part of the molecule.

The amount of ethylene oxide added to the primary alcohol may be atleast about 0.5, preferably from about 1.5 to about 5, most preferablyfrom about 2 to about 4, moles of ethylene oxide per mole of primaryalcohol. It is preferred that at least about 1.5 moles per mole ofprimary alcohol be utilized in order to minimize the amount ofunalkoxylated primary alcohol. It is preferred that no more than about 5moles per mole of primary alcohol be used because above that amount thehydrophilic end of the chain starts to lose its calcium/magnesiumtolerance.

In one embodiment, the hydrocarbon recovery composition may include abranched primary alcohol derivative surfactant as described above. Insome embodiments, an amount of a branched primary alcohol derivativesurfactant in a composition may be greater than about 10 wt. % of thetotal composition. In an embodiment, an amount of a branched primaryalcohol derivative surfactant in the hydrocarbon recovery compositionmay range from about 10 wt. % to about 80 wt. % of the totalcomposition. An amount of a branched primary alcohol derivativesurfactant in the composition may range from about 10 wt % to about 40wt % of the total weight of the composition, preferably from about 20 toabout 30 wt %. The remainder of the composition may include, but is notlimited to, water, low molecular weight alcohols, organic solvents,alkyl sulfonates, aryl sulfonates, brine or combinations thereof. Lowmolecular weight alcohols include, but are not limited to, methanol,ethanol, propanol, isopropyl alcohol, tert-butyl alcohol, sec-butylalcohol, butyl alcohol, tert-amyl alcohol or combinations thereof.Organic solvents include, but are not limited to, methyl ethyl ketone,acetone, lower alkyl cellosolves, lower alkyl carbitols or combinationsthereof.

In one embodiment, the hydrocarbon recovery composition may alsocomprise an enhancing agent to lower the interfacial tension of thehydrocarbon composition. Such enhancing agents may be selected fromalcohols, polymers such as polypropylene glycol and other surfactanttype molecules. Preferably, the enhancing agent may comprise from about1 wt % to about 25 wt % of the hydrocarbon recovery composition.

Manufacture of the Derivatives

The primary alcohols may be ethoxylated and propoxylated by reactingthem with ethylene oxide (EO) and propylene oxide (PO) in the presenceof an appropriate alkoxylation catalyst. It is preferred that thepropoxylation be carried out first followed by the ethoxylation. PO ismore like the carbon chain of the derivative molecule when it comes tohydrophilicity and EO is more like the polar end group of the surfactantderivative molecule. The PO assists in solubilizing one end of thesurfactant derivative molecule in the oil phase and the EO assists insolubilizing the other end of the surfactant derivative molecule in thewater phase. The EO and PO could be added randomly but this would causeloss of control of the transition gradient (oil to water).

The alkoxylation catalyst may be sodium hydroxide which is commonly usedcommercially for alkoxylating alcohols. The primary alcohols may beethoxylated and propoxylated using a double metal cyanide catalyst asdescribed in U.S. Pat. No. 6,977,236 which is herein incorporated byreference in its entirety. The primary alcohols may also be ethoxylatedand propoxylated using a lanthanum-based or a rare earth metal-basedalkoxylation catalyst as described in U.S. Pat. Nos. 5,059,719 and5,057,627, both of which are herein incorporated by reference in theirentirety. Primary alcohol ethoxylate/propoxylates of this invention mayalso be made by reacting an olefin with diethylene glycol or by reactinga haloalkane with mono-, di- or polyglycols.

The primary alcohol ethoxylate/propoxylates may be prepared by adding tothe primary alcohol or mixture of primary alcohols a calculated amount,for example from about 0.1 percent by weight to about 0.6 percent byweight, of a strong base, typically an alkali metal or alkaline earthmetal hydroxide such as sodium hydroxide or potassium hydroxide, whichserves as a catalyst for alkoxylation. An amount of ethylene orpropylene oxide calculated to provide the desired number of moles ofethylene or propylene oxide per mole of primary alcohol is thenintroduced and the resulting mixture is allowed to react until thepropylene oxide is consumed. Suitable reaction temperatures range fromabout 120 to about 220° C.

The primary alcohol ethoxylate/propoxylates of the present invention maybe prepared by using a multi-metal cyanide catalyst as the alkoxylationcatalyst. The catalyst may be contacted with the primary alcohol andthen both may be contacted with the ethylene or propylene oxide reactantwhich may be introduced in gaseous form. The reaction temperature mayrange from about 90° C. to about 250° C. and super atmospheric pressuresmay be used if it is desired to maintain the primary alcoholsubstantially in the liquid state.

Narrow range primary alcohol ethoxylate/propoxylates may be producedutilizing a soluble basic compound of elements in the lanthanum serieselements or the rare earth elements as the alkoxylation catalyst.Lanthanum phosphate is particularly useful. The ethoxylation andpropoxylation are carried out employing conventional reaction conditionssuch as those described above.

It should be understood that the alkoxylation procedure serves tointroduce a desired average number of propylene oxide units per mole ofprimary alcohol ethoxylate/propoxylate. For example, treatment of aprimary alcohol mixture with 1.5 moles of propylene oxide per mole ofprimary alcohol serves to effect the propoxylation of each alcoholmolecule with an average of 1.5 propylene oxide moieties per mole ofprimary alcohol moiety, although a substantial proportion of primaryalcohol moieties will have become combined with more than 1.5 propyleneoxide moieties and an approximately equal proportion will have becomecombined with less than 1.5. In a typical alkoxylation product mixture,there is also a minor proportion of unreacted primary alcohol.

In the preparation of the glycerol sulfonates derived from thealkoxylated primary alcohols of the present invention, the alkoxylatesare reacted with epichlorohydrin, preferably in the presence of acatalyst such as tin tetrachloride at from about 110 to about 120° C.for from about 3 to about 5 hours at a pressure of about 14.7 to about15.7 psia (about 100 to about 110 kPa) in toluene. Next, the reactionproduct is reacted with a base such as sodium hydroxide or potassiumhydroxide at from about 85 to about 95° C. for from about 2 to about 4hours at a pressure of about 14.7 to about 15.7 psia (about 100 to about110 kPa). The reaction mixture is cooled and separated in two layers.The organic layer is separated and the product isolated. It is thenreacted with sodium bisulfite and sodium sulfite at from about 140 toabout 160° C. for from about 3 to about 5 hours at a pressure of about60 to about 80 psia (about 400 to about 550 kPa). The reaction is cooledand the product glycerol sulfonate is recovered as about a 25 wt %active matter solution in water. The reactor is preferably a 500 mlzipperclave reactor.

The primary alcohol alkoxylates may be sulfated using one of a number ofsulfating agents including sulfur trioxide, complexes of sulfur trioxidewith (Lewis) bases, such as the sulfur trioxide pyridine complex and thesulfur trioxide trimethylamine complex, chlorosulfonic acid and sulfamicacid. The sulfation may be carried out at a temperature preferably notabove about 80° C. The sulfation may be carried out at temperature aslow as about −20° C., but higher temperatures are more economical. Forexample, the sulfation may be carried out at a temperature from about 20to about 70° C., preferably from about 20 to about 60° C., and morepreferably from about 20 to about 50° C. Sulfur trioxide is the mosteconomical sulfating agent.

The primary alcohol alkoxylates may be reacted with a gas mixture whichin addition to at least one inert gas contains from about 1 to about 8percent by volume, relative to the gas mixture, of gaseous sulfurtrioxide, preferably from about 1.5 to about 5 percent volume. Inprinciple, it is possible to use gas mixtures having less than 1 percentby volume of sulfur trioxide but the space-time yield is then decreasedunnecessarily. Inert gas mixtures having more than 8 percent by volumeof sulfur trioxide in general may lead to difficulties due to unevensulfation, lack of consistent temperature and increasing formation ofundesired byproducts. Although other inert gases are also suitable, airor nitrogen are preferred, as a rule because of easy availability.

The reaction of the primary alcohol alkoxylate with the sulfur trioxidecontaining inert gas may be carried out in falling film reactors. Suchreactors utilize a liquid film trickling in a thin layer on a cooledwall which is brought into contact in a continuous current with the gas.Kettle cascades, for example, would be suitable as possible reactors.Other reactors include stirred tank reactors, which may be employed ifthe sulfation is carried out using sulfamic acid or a complex of sulfurtrioxide and a (Lewis) base, such as the sulfur trioxide pyridinecomplex or the sulfur trioxide trimethylamine complex. These sulfationagents would allow an increased residence time of sulfation without therisk of ethoxylate chain degradation and olefin elimination by (Lewis)acid catalysis.

The molar ratio of sulfur trioxide to alkoxylate may be 1.4 to 1 or lessincluding about 0.8 to about 1 mole of sulfur trioxide used per mole ofOH groups in the alkoxylate and latter ratio is preferred. Sulfurtrioxide may be used to sulfate the alkoxylates and the temperature mayrange from about −20° C. to about 50° C., preferably from about 5° C. toabout 40° C., and the pressure may be in the range from about 100 toabout 500 kPa abs. The reaction may be carried out continuously ordiscontinuously. The residence time for sulfation may range from about0.5 seconds to about 10 hours, but is preferably from 0.5 seconds to 20minutes.

The sulfation may be carried out using chlorosulfonic acid at atemperature from about −20° C. to about 50° C., preferably from about 0°C. to about 30° C. The mole ratio between the alkoxylate and thechlorosulfonic acid may range from about 1:0.8 to about 1:1.2,preferably about 1:0.8 to 1:1. The reaction may be carried outcontinuously or discontinuously for a time between fractions of seconds(i.e., 0.5 seconds) to about 20 minutes.

Unless they are only used to generate gaseous sulfur trioxide to be usedin sulfation, the use of sulfuric acid and oleum should be omitted.Subjecting any ethoxylate to these reagents leads to ether bondbreaking—expulsion of 1,4-dioxane (back-biting)—and finally conversionof primary alcohol to an internal olefin.

Following sulfation, the liquid reaction mixture may be neutralizedusing an aqueous alkali metal hydroxide, such as sodium hydroxide orpotassium hydroxide, an aqueous alkaline earth metal hydroxide, such asmagnesium hydroxide or calcium hydroxide, or bases such as ammoniumhydroxide, substituted ammonium hydroxide, sodium carbonate or potassiumhydrogen carbonate. The neutralization procedure may be carried out overa wide range of temperatures and pressures. For example, theneutralization procedure may be carried out at a temperature from about0° C. to about 65° C. and a pressure in the range from about 100 toabout 200 kPa abs. The neutralization time may be in the range fromabout 0.5 hours to about 1 hour but shorter and longer times may be usedwhere appropriate.

The ethoxylated/propoxylated branched primary alcohol of this inventionmay be carboxylated by any of a number of well-known methods. It may bereacted with a halogenated carboxylic acid to make a carboxylic acid.Alternatively, the alcoholic end group —CH₂OH— may be oxidized to yielda carboxylic acid. In either case, the resulting carboxylic acid maythen be neutralized with an alkali metal base to form a carboxylatesurfactant.

In a specific example, an ethoxylated/propoxylated branched primaryalcohol may be reacted with potassium t-butoxide and initially heatedat, for example, 60° C. under reduced pressure for, for example, 10hours. It would be allowed to cool and then sodium chloroacetate wouldbe added to the mixture. The reaction temperature would be increased to,for example, 90° C. under reduced pressure for, for example, 20-21hours. It would be cooled to room temperature and water and hydrochloricacid added. This would be heated to, for example, 90° C. for, forexample, 2 hours. The organic layer may be extracted by adding ethylacetate and washing it with water.

Injection of the Hydrocarbon Recovery Composition

The hydrocarbon recovery composition may interact with hydrocarbons inat least a portion of the hydrocarbon containing formation. Interactionwith the hydrocarbons may reduce an interfacial tension of thehydrocarbons with one or more fluids in the hydrocarbon containingformation. In other embodiments, a hydrocarbon recovery composition mayreduce the interfacial tension between the hydrocarbons and anoverburden/underburden of a hydrocarbon containing formation. Reductionof the interfacial tension may allow at least a portion of thehydrocarbons to mobilize through the hydrocarbon containing formation.

The ability of a hydrocarbon recovery composition to reduce theinterfacial tension of a mixture of hydrocarbons and fluids may beevaluated using known techniques. In an embodiment, an interfacialtension value for a mixture of hydrocarbons and water may be determinedusing a spinning drop tensiometer. An amount of the hydrocarbon recoverycomposition may be added to the hydrocarbon/water mixture and aninterfacial tension value for the resulting fluid may be determined. Alow interfacial tension value (e.g., less than about 1 dyne/cm) mayindicate that the composition reduced at least a portion of the surfaceenergy between the hydrocarbons and water. Reduction of surface energymay indicate that at least a portion of the hydrocarbon/water mixturemay mobilize through at least a portion of a hydrocarbon containingformation.

In an embodiment, a hydrocarbon recovery composition may be added to ahydrocarbon/water mixture and the interfacial tension value may bedetermined. An ultralow interfacial tension value (e.g., less than about0.01 dyne/cm) may indicate that the hydrocarbon recovery compositionlowered at least a portion of the surface tension between thehydrocarbons and water such that at least a portion of the hydrocarbonsmay mobilize through at least a portion of the hydrocarbon containingformation. At least a portion of the hydrocarbons may mobilize moreeasily through at least a portion of the hydrocarbon containingformation at an ultra low interfacial tension than hydrocarbons thathave been treated with a composition that results in an interfacialtension value greater than 0.01 dynes/cm for the fluids in theformation. Addition of a hydrocarbon recovery composition to fluids in ahydrocarbon containing formation that results in an ultra-lowinterfacial tension value may increase the efficiency at whichhydrocarbons may be produced. A hydrocarbon recovery compositionconcentration in the hydrocarbon containing formation may be minimizedto minimize cost of use during production.

In an embodiment of a method to treat a hydrocarbon containingformation, a hydrocarbon recovery composition including a carboxylate ora sulfate or a glycerol sulfonate derivative of apropoxylated/ethoxylated branched primary alcohol of this invention maybe provided (e.g., injected) into hydrocarbon containing formation 100through injection well 110 as depicted in FIG. 1. Hydrocarbon formation100 may include overburden 120, hydrocarbon layer 130, and underburden140. Injection well 110 may include openings 112 that allow fluids toflow through hydrocarbon containing formation 100 at various depthlevels. In certain embodiments, hydrocarbon layer 130 may be less than1000 feet below earth's surface. In some embodiments, underburden 140 ofhydrocarbon containing formation 100 may be oil wet. Low salinity watermay be present in hydrocarbon containing formation 100, in otherembodiments.

A hydrocarbon recovery composition may be provided to the formation inan amount based on hydrocarbons present in a hydrocarbon containingformation. The amount of hydrocarbon recovery composition, however, maybe too small to be accurately delivered to the hydrocarbon containingformation using known delivery techniques (e.g., pumps). To facilitatedelivery of small amounts of the hydrocarbon recovery composition to thehydrocarbon containing formation, the hydrocarbon recovery compositionmay be combined with water and/or brine to produce an injectable fluid.An amount of a hydrocarbon recovery composition injected intohydrocarbon containing formation 100 may be from about 0.1 to about 4wt. % of the total weight of the injectable fluid. In certainembodiments, an amount of the derivative (the active matter) which ispart of the hydrocarbon recovery composition provided to a hydrocarboncontaining formation may be from about 0.1 to about 1 wt. % of the totalweight of injectable fluid. In some embodiments, an amount of ahydrocarbon recovery composition provided to a hydrocarbon containingformation may be from about 0.2 to about 0.5 wt. % of the total weightof injectable fluid.

The hydrocarbon recovery composition may interact with at least aportion of the hydrocarbons in hydrocarbon layer 130. The interaction ofthe hydrocarbon recovery composition with hydrocarbon layer 130 mayreduce at least a portion of the interfacial tension between differenthydrocarbons. The hydrocarbon recovery composition may also reduce atleast a portion of the interfacial tension between one or more fluids(e.g., water, hydrocarbons) in the formation and the underburden 140,one or more fluids in the formation and the overburden 120 orcombinations thereof.

In an embodiment, a hydrocarbon recovery composition may interact withat least a portion of hydrocarbons and at least a portion of one or moreother fluids in the formation to reduce at least a portion of theinterfacial tension between the hydrocarbons and one or more fluids.Reduction of the interfacial tension may allow at least a portion of thehydrocarbons to form an emulsion with at least a portion of one or morefluids in the formation. An interfacial tension value between thehydrocarbons and one or more fluids may be altered by the hydrocarbonrecovery composition to a value of less than about 0.1 dyne/cm. In someembodiments, an interfacial tension value between the hydrocarbons andother fluids in a formation may be reduced by the hydrocarbon recoverycomposition to be less than about 0.05 dyne/cm. An interfacial tensionvalue between hydrocarbons and other fluids in a formation may belowered by the hydrocarbon recovery composition to less than 0.001dyne/cm, in other embodiments.

At least a portion of the hydrocarbon recoverycomposition/hydrocarbon/fluids mixture may be mobilized to productionwell 150. Products obtained from the production well 150 may include,but are not limited to, components of the hydrocarbon recoverycomposition (e.g., a long chain aliphatic alcohol and/or a long chainaliphatic acid salt), methane, carbon monoxide, water, hydrocarbons,ammonia, asphaltenes, or combinations thereof. Hydrocarbon productionfrom hydrocarbon containing formation 100 may be increased by greaterthan about 50% after the hydrocarbon recovery composition has been addedto a hydrocarbon containing formation.

In certain embodiments, hydrocarbon containing formation 100 may bepretreated with a hydrocarbon removal fluid. A hydrocarbon removal fluidmay be composed of water, steam, brine, gas, liquid polymers, foampolymers, monomers or mixtures thereof. A hydrocarbon removal fluid maybe used to treat a formation before a hydrocarbon recovery compositionis provided to the formation. Hydrocarbon containing formation 100 maybe less than 1000 feet below the earth's surface, in some embodiments. Ahydrocarbon removal fluid may be heated before injection into ahydrocarbon containing formation 100, in certain embodiments. Ahydrocarbon removal fluid may reduce a viscosity of at least a portionof the hydrocarbons within the formation. Reduction of the viscosity ofat least a portion of the hydrocarbons in the formation may enhancemobilization of at least a portion of the hydrocarbons to productionwell 150. After at least a portion of the hydrocarbons in hydrocarboncontaining formation 100 have been mobilized, repeated injection of thesame or different hydrocarbon removal fluids may become less effectivein mobilizing hydrocarbons through the hydrocarbon containing formation.Low efficiency of mobilization may be due to hydrocarbon removal fluidscreating more permeable zones in hydrocarbon containing formation 100.Hydrocarbon removal fluids may pass through the permeable zones in thehydrocarbon containing formation 100 and not interact with and mobilizethe remaining hydrocarbons. Consequently, displacement of heavierhydrocarbons adsorbed to underburden 140 may be reduced over time.Eventually, the formation may be considered low producing oreconomically undesirable to produce hydrocarbons.

In certain embodiments, injection of a hydrocarbon recovery compositionafter treating the hydrocarbon containing formation with a hydrocarbonremoval fluid may enhance mobilization of heavier hydrocarbons absorbedto underburden 140. The hydrocarbon recovery composition may interactwith the hydrocarbons to reduce an interfacial tension between thehydrocarbons and underburden 140. Reduction of the interfacial tensionmay be such that hydrocarbons are mobilized to and produced fromproduction well 150. Produced hydrocarbons from production well 150 mayinclude, in some embodiments, at least a portion of the components ofthe hydrocarbon recovery composition, the hydrocarbon removal fluidinjected into the well for pretreatment, methane, carbon dioxide,ammonia, or combinations thereof. Adding the hydrocarbon recoverycomposition to at least a portion of a low producing hydrocarboncontaining formation may extend the production life of the hydrocarboncontaining formation. Hydrocarbon production from hydrocarbon containingformation 100 may be increased by greater than about 50% after thehydrocarbon recovery composition has been added to hydrocarboncontaining formation. Increased hydrocarbon production may increase theeconomic viability of the hydrocarbon containing formation.

Interaction of the hydrocarbon recovery composition with at least aportion of hydrocarbons in the formation may reduce at least a portionof an interfacial tension between the hydrocarbons and underburden 140.Reduction of at least a portion of the interfacial tension may mobilizeat least a portion of hydrocarbons through hydrocarbon containingformation 100. Mobilization of at least a portion of hydrocarbons,however, may not be at an economically viable rate.

In one embodiment, polymers and/or monomers may be injected intohydrocarbon formation 100 through injection well 110, after treatment ofthe formation with a hydrocarbon recovery composition, to increasemobilization of at least a portion of the hydrocarbons through theformation. Suitable polymers include, but are not limited to, CIBA®ALCOFLOOD®, manufactured by Ciba Specialty Additives (Tarrytown, N.Y.),Tramfloc® manufactured by Tramfloc Inc. (Temple, Ariz.), and HE®polymers manufactured by Chevron Phillips Chemical Co. (The Woodlands,Texas). Interaction between the hydrocarbons, the hydrocarbon recoverycomposition and the polymer may increase mobilization of at least aportion of the hydrocarbons remaining in the formation to productionwell 150.

The propoxylated branched primary alcohol glycerol derivative componentof the composition is thermally stable and may be used over a wide rangeof temperature. In some embodiments, a hydrocarbon recovery compositionmay be added to a portion of a hydrocarbon containing formation 100 thathas an average temperature of from 0 to 150° C. because of the highthermal stability of the glycerol derivative.

In some embodiments, the hydrocarbon recovery composition may beinjected into hydrocarbon containing formation 100 through injectionwell 110 as depicted in FIG. 2. Interaction of the hydrocarbon recoverycomposition with hydrocarbons in the formation may reduce at least aportion of an interfacial tension between the hydrocarbons andunderburden 140. Reduction of at least a portion of the interfacialtension may mobilize at least a portion of hydrocarbons to a selectedsection 160 in hydrocarbon containing formation 100 to form hydrocarbonpool 170. At least a portion of the hydrocarbons may be produced fromhydrocarbon pool 170 in the selected section of hydrocarbon containingformation 100.

In other embodiments, mobilization of at least a portion of hydrocarbonsto selected section 160 may not be at an economically viable rate.Polymers may be injected into hydrocarbon formation 100 to increasemobilization of at least a portion of the hydrocarbons through theformation. Interaction between at least a portion of the hydrocarbons,the hydrocarbon recovery composition and the polymers may increasemobilization of at least a portion of the hydrocarbons to productionwell 150.

In some embodiments, a hydrocarbon recovery composition may include aninorganic salt (e.g. sodium carbonate (Na₂CO₃), sodium chloride (NaCl),or calcium chloride (CaCl₂)). The addition of the inorganic salt mayhelp the hydrocarbon recovery composition disperse throughout ahydrocarbon/water mixture. The enhanced dispersion of the hydrocarbonrecovery composition may decrease the interactions between thehydrocarbon and water interface. The decreased interaction may lower theinterfacial tension of the mixture and provide a fluid that is moremobile.

EXAMPLES Example 1

Neodol 67 branched primary alcohol (carbon number 16-17, average numberof branches per aliphatic group about 1.5) was dried over 4A molecularsieves. The alcohol was further purged with Nitrogen at 120° C. whilestirring for 1 hr in a round bottom flask equipped with over headstirrer, reflux condenser thermocouple and Dean Stark trap.

The alcohol was kept under nitrogen until loaded into a clean autoclavewith a lanthanum phosphate (LAPO) catalyst. LAPO was charged at the rateof 0.5 g/150 g of starting alcohol. The reaction was run with 1050 g ofNeodol 67 alcohol, 3.533 g of LAPO and 1305 g of propylene oxide to makea 7 mole PO per molecule of Neodol 67 alcohol. The autoclave was sealedand purge with nitrogen to create a nitrogen atmosphere. The startingnitrogen was 30 psi (200 kPa) at 160° C. The propylene oxide (PO) wascharged in using a dome regulator to control flow. The actualtemperature was between 160° C. to 171° C. and pressure is 30 psi (200kPa) to 165 psi (1140 kPa). PO was added over the course of 180 minutesand the reaction was allowed to soak for 30 minutes after the additionof PO was complete. 282 grams of ethylene oxide (EO) was added over 30minutes to make a 2 mole cap of EO. The reaction temperature was about140° C. and the reaction was allow to soak (to stir it at temperaturewithout adding any more reagents) for 30 minutes after the EO additionwas complete. The reactor contents were then discharged and collected.

The Neodol 67 PO/EO material was derivatized to a carboxylate derivativewith sodium chloroacetate using the procedure in U.S. Pat. No.4,098,818, Example 1 part A. 50.2 grams (0.068 moles) of the NEODOL 67PO/EO produced in the previous experiment was mixed with 8.7 grams(0.075 moles-1.1 fold excess) of sodium chloroacetate and 1 gram (0.01moles) of a 50% aqueous sodium hydroxide solution. The pressure wasreduced to 10 millimeters of mercury and the mixture was heated to 80degree C. and the thick mixture was stirred for 2 hours. Aftercompletion of the reaction, the product was heated to 150 degrees C. andstirred for an additional hour to remove water. The product was analyzedby NMR and showed a conversion of about 93%.

Interfacial tensions (IFT's) were measured for a North Sea crude oilwith 3.1% Seawater Brine at 72° C. Compositions and interfacial tensionmeasurements are shown in FIG. 3. The compositions described in FIG. 3were made by mixing the Carboxylate hydrocarbon recovery compositionwith seawater brine and a North Sea crude oil at 72° C. to obtain a 0.2wt % active matter solution.

Interfacial tension values for the hydrocarbon/hydrocarbon recoverycomposition/water mixtures were determined using a University of Texasmodel spinning drop tensiometer. A four microliter (μL) drop ofn-dodecane hydrocarbon was placed into a glass capillary tube thatcontained a hydrocarbon recovery composition/brine solution to provide abrine-to-hydrocarbon volume ratio of 400. The tube was placed into aspinning drop apparatus and then capped. The motor was turned on rapidlyto rotate the tube to create a cylindrical drop within the tube (e.g. 6to 12 ms/rev). The drop length may be greater than or equal to 4 timesthe width of a drop. The capillary tube and drop were heated to varioustemperatures (at and above 25, 50, 75 and 98° C.). The drop was videotaped for later replay for measurement of the drop dimensions andcalculation of the interfacial tension between the drop and thecomposition/brine using an Optima® System. The time range of themeasurements was from about 0.1 to about 1.0 hours to achieve dropequilibrium.

Further modifications and alternative embodiments of various aspects ofthe invention may be apparent to those skilled in the art in view ofthis description. Accordingly, this description is to be construed asillustrative only and is for the purpose of teaching those skilled inthe art the general manner of carrying out the invention. It is to beunderstood that the forms of the invention shown and described hereinare to be taken as the presently preferred embodiments. Elements andmaterials may be substituted for those illustrated and described herein,parts and processes may be reversed, and certain features of theinvention may be utilized independently, all as would be apparent to oneskilled in the art after having the benefit of this description to theinvention. Changes may be made in the elements described herein withoutdeparting from the spirit and scope o the invention as described in thefollowing claims. In addition, it is to be understood that featuresdescribed herein independently may, in certain embodiments, be combined.

What is claimed is:
 1. A method of treating a hydrocarbon containingformation, comprising: (a) providing a composition to at least a portionof the hydrocarbon containing formation, wherein the compositioncomprises a carboxylate derivative of an ethoxylated/propoxylatedprimary alcohol having a branched aliphatic group with an average carbonnumber from 10 to 24 and having an average number of branches peraliphatic group of from 0.7 to 2.5 and having at least 0.5-moles ofpropylene oxide per mole of primary alcohol and having at least 0.5moles of ethylene oxide per mole of primary alcohol; and (b) allowingthe composition to interact with hydrocarbons in the hydrocarboncontaining formation.
 2. The method of claim 1 wherein the branchedaliphatic group of the ethoxylated/propoxylated primary alcohol has anaverage number of branches per aliphatic group of from 1.4 to
 2. 3. Themethod of claim 1 wherein the composition is admixed with water and/orbrine to form an injectable fluid which is injected into the hydrocarboncontaining formation and the derivative comprises from 0.1 to 1 wt % ofthe injectable fluid.
 4. The method of claim 3 wherein the derivativecomprises from 0.2 to 0.5 wt % of the injectable fluid.
 5. The method ofclaim 1 wherein the ethoxylated/propoxylated primary alcohol has anaverage of from 4 to 7 propylene oxide groups per molecule and anaverage of from 2 to 4 ethylene oxide groups per molecule.
 6. The methodof claim 1 wherein the branched aliphatic group of theethoxylated/propoxylated primary alcohol has an average carbon numberfrom 14 to
 20. 7. The method of claim 1 wherein the composition alsocomprises an enhancing agent.
 8. The method of claim 1 wherein thederivative comprises from 10 to 80 wt % of the composition.
 9. Ahydrocarbon recovery composition comprising a carboxylate derivative ofan ethoxylated/propoxylated primary alcohol having a branched aliphaticgroup with an average carbon number from 10 to 24 and having an averagenumber of branches per aliphatic group of from 0.7 to 2.5 and having atleast 0.5 moles of propylene oxide per mole of primary alcohol andhaving at least 0.5 moles of ethylene oxide per mole of primary alcohol.10. The composition of claim 9 wherein greater than about 50 percent ofthe branches of the branched aliphatic group of theethoxylated/propoxylated primary alcohol are methyl groups.
 11. Thecomposition of claim 9 wherein the primary alcohol has less than about0.5 percent aliphatic quaternary carbon atoms.
 12. The composition ofclaim 9 wherein the ethoxylated/propoxylated primary alcohol has anaverage of from 4 to 7 propylene oxide groups per molecule and anaverage of from 2 to 4 ethylene oxide groups per molecule.
 13. Thecomposition of claim 9 wherein the branched aliphatic group of theethoxylated/propoxylated primary alcohol has an average carbon numberfrom 14 to 20.